Article pubs.acs.org/EF
Enhanced Oil Recovery (EOR) by Combining Surfactant with Low Salinity Injection Annette Meland Johannessen* and Kristine Spildo Centre for Integrated Petroleum Research (Uni CIPR), University of Bergen, Allégaten 41, 5007 Bergen, Norway ABSTRACT: When injecting low salinity (LS) water, it is believed that destabilization of oil layers adhering to mineral surfaces could be a contributing mechanism to enhanced oil recovery (EOR). Surfactant flooding is a proven EOR technique by increasing the capillary number. The combination of LS water at reduced capillarity can avoid retrapping of destabilized oil and exceed recoveries of either of the techniques applied alone. In this study, we have used an alcohol propoxy sulfate mixed with an internal olefin sulfonate to compare the oil recovery in a low salinity surfactant (LSS) flooding process at moderately low IFTs to that of an optimal salinity surfactant (OSS) injection process at ultralow IFT. The surfactant formulation was selected on the basis of an initial screening phase using a North Sea crude oil and diluted seawater. Its effect on oil recovery efficiency in different injection scenarios was investigated using crude oil aged Berea sandstone cores. The results showed comparable recoveries for the LSS flooding at a capillary number 2 orders of magnitude lower than that for the surfactant flooding at ultralow IFT. In addition, retention values in the latter case were around 60% higher than for the LS case. On the basis of this, it appears that the LSS process may be more economically efficient than an OSS injection process at ultralow IFT.
1. INTRODUCTION Low salinity (LS) water injection is an emerging enhanced oil recovery (EOR) technique1−10 where it is believed that destabilization of oil layers adhering to mineral surfaces could be a contributing mechanism. Surfactant flooding is a proven EOR technology where surfactant added to the injection water improves recovery by increasing the capillary number.11−13 The capillary number, Nc, refers to the dimensionless ratio of viscous to capillary forces, which commonly is defined as uμ Nc = (1) σ
case, the process should not work on water-wet cores. However, Ashraf el al.39 found that although the ultimate oil recovery was largest for neutral wet Berea cores, the largest LSE was found for water-wet conditions. Thus, at present, there is no consistent correlation between wettability and LSE. Spildo et al.9 showed that even though LS injection alone gave negligible oil recovery, a combination of LS and surfactant flooding on intermediate-wet cores gave higher recoveries than what would be predicted by the relationship between capillary number and residual oil saturation for Berea, published by Garnes et al. 12 This was achieved at low surfactant concentration with a moderate reduction in IFT showing low retention values. APS and IOS Surfactants. Alcohol propoxy sulfates (APS) have previously been studied for EOR purposes. The propoxy (PO) groups are weakly hydrophobic functional groups that have affinity for the interface and thus increase the width of the ultralow IFT region.15 The degree of propoxylation can be used to tailor the surfactant to a given crude oil, temperature, and salinity, as the addition of PO groups lowers optimum salinity. Further, the presence of PO groups also adds calcium tolerance to the surfactant.16−20 The use of PO groups, and branching of such, also tends to decrease the order of micellar structures. This again tends to reduce equilibration time and promotes the formation of microemulsions instead of unwanted gel and other viscous phases. Sulfate surfactants, however, have limited temperature stability and are restricted to reservoirs up to approximately 60 °C. At higher temperatures, the sulfates tend to hydrolyze.15 Ideally, one would like to limit the number of components in a surfactant formulation, i.e. surfactant, cosurfactant, and
where u is the Darcy velocity, μ is the viscosity of the displacing fluid, and σ is the interfacial tension between the oil and the displacing fluid. Increasing Nc reduces the amount of oil retained in the formation by capillary forces and/or remobilizes oil that is already capillary trapped. By combining these two techniques in a low salinity surfactant (LSS) injection process, an increase in recovery that exceeds that of either of the techniques applied alone has been observed.8,9 Even though many studies have shown a negligible response to LS injection, the most encouraging results show up to 25% OOIP additional recovery.14 Compositions of LS injection water used in field tests range from 2 to 3000 ppm;14 however, the low salinity effect (LSE) has been reported for brine compositions of up to 5000 ppm.8 Despite growing interest in low salinity brine injection for EOR purposes, a consistent mechanistic explanation of the LSE has not yet emerged.14 As noted by the authors, the various circumstances under which LSE may or may not be observed indicates that there are probably more than one contributing mechanism. The type and amount of clays present has been suggested as important for LSE. Nonetheless, wettability change from less to more waterwet conditions is the most frequently suggested cause of increased recovery by low salinity brine injection. If that is the © XXXX American Chemical Society
Received: April 4, 2013 Revised: September 2, 2013
A
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anionic surfactants is complex. Healy et al.28 reported that S* increases as WOR increases. On the other hand, Tien and Bettahar26 found a decrease in S* with increasing WOR for sodium dodecyl benzene sulfonate, while Flaaten et al.27 found a slight decrease in S* with decreasing total surfactant concentration for an APS-IOS surfactant system. Surfactant concentrations during the phase behavior screening process are also usually higher than what is normally used in a flooding process. However, lowering the surfactant concentration may cause changes in the phase behavior system. Salager et al.25 stated that the optimum surfactant solution, obtained from minimum IFT at low surfactant concentration and no detectable three-phase behavior, can be correlated to S* that normally is found for high surfactant concentration from three-phase behavior and minimum IFT. Wu et al.17 relied solely on IFT measurements when searching for optimal salinity for branched APS surfactants for improved oil recovery. In this study, an APS and IOS1518 blend is used to compare the oil recovery in a combined LSS flooding process at moderately low IFTs to that of a surfactant injection process at ultralow IFT. The surfactant formulation was selected on the basis of an initial phase behavior screening process and IFT measurements where variation in surfactant concentration and WOR have been taken into consideration, using a North Sea crude oil and diluted synthetic seawater (SW). The effect on oil recovery efficiency in different injection scenarios was investigated using crude oil aged Berea sandstone cores. Surfactant retention was also measured and compared in the LS and the high salinity regimes to highlight the economic benefit from operating in a LS environment.
cosolvent, as much as possible. This gives the system added robustness and eliminates possible challenges related to chromatographic separation of the components. However, in many cases, mixtures are needed to avoid the formation of highly viscous phases and obtain clear, stable surfactant solutions that are suitable for injection. Earlier studies have shown that mixed surfactant systems of APS with different carbon chain cuts of internal olefin sulfonate (IOS) ranging from C15 to C28 provide advantages in matching a system to specific conditions,21−23 in addition to showing no measurable chromatographic separation during core floods.37 The mixed surfactant systems can improve microemulsion phase behavior with a wider salinity window in the Winsor III region, improve aqueous solubility, show good tolerance of divalent ions, and require low cosolvent concentrations, or even no cosolvent. It should also be noted that APSs have previously been reported to give low IFT and high oil mobilization without the addition of cosurfactants or cosolvents.22,23 Phase Behavior. In the following, we classify microemulsion systems as Winsor I, Winsor II, or Winsor III.24 Winsor I and II refer to two phase equilibrium between a microemulsion and an excess phase: in a Winsor I system, the equilibrium is between oil-in-water microemulsion and an upper excess oil phase, whereas in the Winsor II system the equilibrium is between a water-in-oil microemulsion and a lower excess water phase. The Winsor III system has a middle microemulsion phase in equilibrium with an upper excess oil phase and a lower excess water phase. At optimal salinity (S*) or OS, the middle microemulsion phase solubilizes equal volumes of oil and water. The volume of oil or water per volume of surfactant at S* is referred to as the solubilization parameter at optimum SP*:
SP* =
Vo V = w Vs Vs
2. EXPERIMENTAL SECTION 2.1. Fluids. The compositions of the brines used in the flooding experiments are listed in Table 1.
(2)
Table 1. Concentration [ppm] and Ionic Strength [mol/kg] of SW and Dilutions of SW
where Vi is the volume of oil (o), water (w), and surfactant (s). The middle microemulsion phase has been reported to show very low IFTs against oil and water,28−30 with a minimum when the microemulsion phase contains equal amounts of oil and water. The interfacial tension between oil and water (σ) at an optimum can be calculated using the Chun Huh relation:30 C σ= (SP*)2
0.43 × SW (OS brine)
SW
(3)
C is an empirical constant, usually 0.3 mN/m. Changing variables such as salinity, type of oil, cosolvent, surfactant concentration, and water−oil ratio (WOR) will lead to a shift in phase behavior. For example, for anionic surfactants the phase behavior changes from Winsor I → Winsor III → Winsor II as the salinity increases. The opposite is observed when the alkane carbon number (ACN) of the oil phase increases, i.e., the phase behavior changes from Winsor II → Winsor III → Winsor I as S* increases.25 Standard procedures, like using NaCl brines, high surfactant concentration, alkanes as an oil phase, and 1:1 WOR, are usually used when performing phase behavior experiments in order to quickly screen surfactants and obtain comparable data sets across different studies. However, a phase behavior study with 1:1 WOR may not be representative of a surfactant flooding experiment, which is conducted at residual oil saturation, Sor. Salager et al.25 claimed that the effect of varying surfactant concentration and WOR on the system type for
0.07 × SW (LS brine)
ions
[ppm]
I [mol/kg]
[ppm]
I [mol/kg]
[ppm]
I [mol/kg]
Na+ Ca2+ Mg2+ K+ Cl− SO42− HCO3− SUM
11185 474 1332 359 20186 2749 145 36431
0.243 0.024 0.110 0.005 0.285 0.057 0.001 0.724
4760 202 567 153 8590 1170 62 15503
0.103 0.010 0.047 0.002 0.121 0.024 0.0 0.308
793 34 94 25 1432 195 10 2584
0.017 0.002 0.008 0.0 0.020 0.004 0.0 0.051
Ionic strength, I, is defined as
I=
1 2
n
∑ cizi2 i=1
(4)
where c is molality [mol/kg] and z is the valence of the ion. The 0.43 × SW brine is the concentration where ultralow IFTs were obtained and will be referred to as the optimal salinity (OS) brine in the following. The 0.07 × SW one is the low salinity (LS) brine. In static phase behavior tests, different dilutions of SW than those mentioned in Table 1 were used, as well as different concentrations of pure sodium chloride (NaCl) brines. Surfactant Solutions. A series of branched C12−13 alcohol−xPO− sulfates (x = 7, 9, and 13) with purities of 32%, 27%, and 28%, B
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respectively, were evaluated through phase behavior experiments. They were tested in mixtures with an internal olefin sulfonate cosurfactant with a C15−18 hydrocarbon chain length (IOS1518) with a purity of 33%. Secondary butanol (SBA) was used as a cosolvent. All of the surfactants used in this study were supplied by Shell. Oils. The oils used in this study and their physical properties at 50 °C are listed in Table 2.
Table 4. Core Properties, Aging Oil, and Time for Each Core
Table 2. Oil Density (ρ) and Viscosity (μ) at 50 °C oil C8 C10 crude crude crude crude
A A mod (25% xylene) B B mod (23% xylene)
ρ (g/cm3)
μ (mPa·s)
0.68 0.71 0.85 0.87 0.906 0.893
0.39 0.63 20 3.3
core
Swi
Kw [mD]
aging oil
aging time
L1 L2 L3 H1 H2
0.33 0.32 0.30 0.26 0.34
100 100 85 330 320
crude A “ “ crude B “
2 weeks “ “ 4 weeks “
The dimensions of the cores are similar with core lengths around 10 cm, cross-sectional areas around 11 cm2, PVs around 22 mL, and porosity around 20%. Dry core samples were mounted in Hassler core holders with an overburden pressure of 20 bar, and saturated with SW under vacuum to determine pore volumes (PVs) and porosities. Absolute permeabilities to water were measured at 100% SW saturation before the cores were drained with filtered crude oil to establish initial water saturation, Swi. The cores were aged at 110 °C in order to get a wettability state other than strongly water-wet. L1−L3 were aged for two weeks, while H1 and H2 were aged for four weeks due to delayed initialization of the core flooding experiments. It should be noted, however, that equal amounts of oil were flushed through each of the cores during the aging process. After aging, crude oil was displaced by four PVs of crude A mod or crude B mod, which were used for relative permeability measurements and otherwise throughout the experiments. Figure 1 shows an illustration of the core displacement setup. The displacement experiments were carried out at 50 °C at an injection rate of 0.1 mL/min followed by increased injection rates of 0.5 and 1 mL/min, after each injection step to minimize capillary end effects. Relative permeabilities were measured after each injection step. The coreflooding tests were either performed in tertiary (cores L1−L3) or secondary mode (cores H1 and H2). Tertiary mode refers to a flooding sequence starting with an initial SW flood to establish residual oil saturation, Sorw, followed by a waterflood at reduced salinity, and finally surfactant injection at reduced salinity. In secondary mode, the SW flooding step is omitted, and brine with reduced salinity was injected directly at Swi, followed by surfactant injection at reduced salinity. The process of combining LS brine injection with a reduced capillarity environment is referred to as LSS injection. The LSS injection was evaluated using cores L1, L3, and H1. Cores L2 and H2, on the other hand, were flooded with a surfactant solution at OS (0.43 × SW). This salinity is associated with a minimum in IFT for the selected surfactant system, but it is too high for a low salinity effect14 and will be referred to as optimal salinity surfactant (OSS) in the following. Thus, these experiments are representative of classical surfactant injection experiments. 2.4. Dispersion Measurements. To gain better understanding of the fluid flow in the core material, both with and without laminations, dispersion measurements were conducted at Sor and at 100% water saturation. Dispersion profiles for all the cores at Sor and at 100% water saturation after cleaning were obtained by measuring the effluent resistance when brine with a different salinity from the connate brine (i.e., different resistance) was injected. 2.5. Retention Measurements. In addition to measuring the effluent surfactant concentration after the core flooding experiments, surfactant retention experiments with retention profiles were performed on two cores, R1 and R2, at 100% water saturation. The
3.3
The alkanes, n-octane (C8) and n-decane (C10), were only used in static phase behavior experiments for initial screening of surfactants. Crudes A and B are North Sea crude oils coming from the same reservoir, only from different batches. Crude B was the oil supplied when the supply of crude A ran out. Crude A was used for aging three cores with permeabilities around 100 mD, cores L1−L3, and crude B was used for aging two cores with permeabilities around 300 mD, cores H1 and H2. Before the flooding experiments started, the crudes were modified with the addition of xylene to obtain a more representative viscosity ratio under typical North Sea reservoir conditions. The amount added was a trade-off between achieving a low viscosity and a low dilution factor. After the aging procedure, crude A mod and crude B mod were used to flush through cores L1− L3 and cores H1 and H2, respectively, to replace the aging oil. 2.2. Static Phase Behavior Screening and IFT Measurements. Test samples were prepared by adding a fixed amount of surfactant, cosurfactant, and cosolvent to NaCl brines or diluted SW brines of varying salinities and mixed with the appropriate oil. The samples were prepared in specially designed, graduated pressure tubes, placed in mixing rigs, and stored in heating cabinets at 50 °C. Solubilization parameters (SPi) were obtained by measuring the phase heights in the samples after equilibrium was reached. S* was determined by the intersection point when SPw and SPo were plotted as a function of salinity. IFTs were measured at a total surfactant concentration of 0.2 wt % (3:1 surfactant, cosurfactant ratio) with 0.2 wt % SBA for various diluted SW brines at 50 °C. The surfactant solutions were measured against crude A mod and crude B mod using a spinning drop tensiometer (SITE100 from KRÜ SS). 2.3. Core Material and Core Preparation. Berea sandstone was used as the core material in this study. Table 3 shows the Berea core mineralogy, clay type, and content for a typical core from the batch of Berea used. The cores designated L1−L3 come from a heterogeneous core material containing visual deformation bands/lamina. The host rock which represents the largest part of the rock was characterized as homogeneous. The deformation bands stretch along the core with a lower porosity and permeability than the host rock, giving absolute permeabilites to water (Kw) of around 100 mD. The cores designated H1−H2 had a Kw around 300 mD and did not contain visible laminations. Core properties and aging procedures are summarized in Table 4.
Table 3. Berea Core Mineralogy mineral content clay type content
quartz 87.5
K feldspar 1.9 smectite 0.0
plagioclase
calcite
dolomite
siderite
pyrite
0.9
TR
0.9
0.9
0.0
clay 7.9
mica
kaolinite
chlorite
3.0
3.2
1.7
C
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Figure 1. Illustration of the experimental setup for dynamic core displacements. cores are from the laminated material and have similar core properties to those of L1−L3. Surfactant concentration was measured by a potentiometric autotitrator from Metrohm. The effluent surfactant samples were titrated against a cationic surfactant supplied by Metrohm, a dialkyl methylimidazolium chloride called TEGOtrant A100. The pH’s in the effluent fractions were measured using a standard pH electrode.
3. RESULTS AND DISCUSSION 3.1. Phase Behavior and Interfacial Tension. The goal of the phase behavior studies was to find a surfactant formulation which could show ultralow IFT at a salinity too high for a LS effect to be expected and at the same time show low, but not ultralow, IFT at a salinity considered to be in the LS region. That way, we can compare the efficiency of the two processes of low salinity surfactant (LSS) injection and surfactant injection at optimal salinity (OSS) in terms of increased oil recovery and surfactant retention. In order to be used in coreflood experiments, the surfactant formulation has to fulfill certain requirements. The aqueous surfactant solution should be stable with no precipitation or phase separation at the given temperature and salinity. A further requirement is a low tendency to form viscous phases. Such phases tend to form outside the three phase region,18 which is important to prevent, especially since the LSS flooding experiments takes place here. The surfactant formulation should also have as short of an equilibration time as possible. Ideally, one would like to limit the number of components in a surfactant formulation to increase the system’s robustness and get simpler logistics for an off-shore operation. Therefore, phase behavior studies were initially performed without the addition of cosurfactant or cosolvent to the NaCl brine. However, the results showed poor phase behavior characteristics; highly viscous phases formed over a wide salinity range with no visible three phase region. Adding cosolvent, SBA, and a small amount of IOS1518 as a cosurfactant improved the phase behavior. However, at salinities outside the three phase region, viscous phases still remained (see Figure 2). Equilibration times were on the order of three weeks. Since some of the flooding experiments will take place at LS conditions in the Winsor I region, it is important to eliminate viscous behavior here. To achieve this, the surfactant to cosurfactant ratio was further reduced due to viscous behavior outside the Winsor III region. A 3:1 ratio of APS to IOS1518 has proven successful in other studies15,19,27 and was thus selected. In this case, the total surfactant concentration was kept at 3.33 wt % with 3 wt % SBA added as the cosolvent in NaCl brine. Results of the phase behavior tests are summarized
Figure 2. Phase behavior for 2 wt % total surfactant concentration (7:1 ratio of C12−13PO9-to-IOS1518) and 2 wt % SBA with n-decane (WOR = 1:1) as a function of NaCl concentration. Salinity is given as % NaCl at the base of the tubes and increases from left to right. Note the viscous phases outside the III phase region.
in Table 5. Compared to the formulation with a 7:1 ratio, this formulation showed reduced equilibration time (
